After drilling a hole through a subsurface formation and determining that the formation can yield an economically sufficient amount of oil or gas, a crew completes the well. During drilling, completion, and production maintenance, personnel routinely insert and/or extract devices such as tubing, tubes, pipes, rods, hollow cylinders, casing, conduit, collars, and duct into the well. For example, a service crew may use a workover or service rig to extract a string of tubing and sucker rods from a well that has been producing petroleum. The crew may inspect the extracted tubing and evaluate whether one or more sections of that tubing should be replaced due physical wear, thinning of the tubing wall, chemical attack, pitting, or another defect. The crew typically replaces sections that exhibit an unacceptable level of wear and notes other sections that are beginning to show wear and may need replacement at a subsequent service call.
As an alternative to manually inspecting tubing, the service crew may employ an instrument to evaluate the tubing as the tubing is extracted from and/or inserted into the well. The instrument typically remains stationary at the wellhead, and the workover rig moves the tubing through the installment's measurement zone.
The instrument typical measures pitting and wall thickness, and can also identity cracks in the tubing wall. Radiation, field strength (electrical, electromagnetic, or magnetic), sonic/ultrasonic signals, and/or pressure differential may interrogate the tubing to evaluate these wear parameters. The instrument typically produces a raw analog signal and outputs a sampled or digital version of that analog signal.
The instrument typically stimulates a section of the tubing using a field, radiation, or pressure and detects the tubing's interaction with or response to the stimulus. An element, such as a transducer, converts the response into an analog electrical signal. For example, the instrument may create a magnetic field into which the tubing is disposed, and the transducer may detect changes or perturbations in the field resulting from the presence of the tubing and any anomalies of that tubing.
The analog electrical signal output by the transducer can have an arbitrary or essentially unlimited number of states or measurement possibilities. Rather than having two discrete or binary levels, typical transducers produce signals that can assume any of numerous levels or values. As tubing passes through the measurement field of the instrument, the analog transducer signal varies in response to variations and anomalies in the wall of the moving tubing.
The transducer and its associated electronics may have a dampened or lagging response that tends to reduce the responsiveness of the signal to tubing wall variations and/or noise. In other words, the instrument may acquire and process analog signals in a manner that steadies or stabilizes those analog signals. In typical conventional instruments, the analog processing remains fixed. Any damping or filtering of those signals is generally constant and inflexible.
The instrument also typically comprises a system, such as an analog-to-digital converter (“ADC”), that converts the analog transducer signal into one or more digital signals suited for reception and display by a computer. In conventional instruments, those digital signals typically provide a “snapshot” of the transducer signal. The ADC typically outputs a number, or set of a numbers, that represents or describes the analog transducer signal at a certain instant or moment in time. Because the analog transducer signal describes the section of tubing that is in the instrument's measurement zone, the digital signal is effectively a sample or a snapshot of a parameter-of-interest of that tubing section.
The analog-to-digital conversion typically occurs on a fixed-time basis, for example one, eight, or sixteen times per second. That is, conventional instruments usually acquire measurement samples at a predetermined rate or on a fixed time interval. Meanwhile, the speed of the tubing passing through the measurement zone may fluctuate or change erratically. The operator may change the extraction speed in an unrepeatable fashion or in a manner not known in advance, a priori, or before the speed-change event.
The instrument may output a series of samples or digital snapshots with each sample separated by a tubing length not readily determined using conventional technology. The separation between samples may be a millimeter, a centimeter, or a meter of tubing length, for example. Distance between samples may vary, fluctuate, or change erratically as the operator changes the tubing speed. Moreover, sample data may blur or become smeared when the tubing is moving rapidly. Consequently, fixing the time interval between each snapshot and allowing the tubing speed to vary between snapshots, as occurs in most conventional instruments, can produce data that is difficult to interpret or fails to adequately characterize the tubing.
Another shortcoming of conventional instruments is that they generally provide an insufficient or limited level of processing of the digital samples. When the tubing is moving slowly through the instrument's measurement zone or is stationary, an operator may incorrectly interpret variation in the digital samples as a wall defect; however, the variation may actually result from an extraneous effect or signal noise. At slow tubing speeds, signal spikes due to noise or a random event can be mistaken for a defective tubing condition.
Meanwhile, when the tubing is moving quickly through the measurement zone, the tubing motion may blur or smooth signal spikes that are actually due to tubing defects, thereby hiding those defects from operator observation. That is, with conventional instruments, high-speed tubing motion may mask or obscure tubing wall defects. This phenomenon can be likened to the image blurring that can occur when a person takes a photograph of a fast moving car. Conventional technologies often fail to differentiate between signal features that indicate the presence of valid tubing defects and other signal features caused by phenomena unrelated to tubing defects. An observer may struggle to determine with confidence whether actual tubing defects are associated with signal anomalies, for example.
Beyond the limitations associated with validating tubing data, conventional instrumentation technologies typically provide little or no capabilities for data interpretation. A well may have a chemical condition that causes tubing corrosion or that negatively impacts production. The sucker rods may exhibit harmonic oscillations that cause premature tubing wear, also inhibiting production. Identifying these or other well conditions is generally difficult using conventional techniques for presentation and manual review of tubing data.
To address these representative deficiencies in the art, an improved capability for processing data is needed, for example in a petroleum application wherein the data is collected from tubing that has been disposed in an oil well. A need also exists for a method to determine whether structures or features in the data are valid and/or indicate the presence of a tubing defect. A further need exists for a capability to interpret tubing data so as to deduce from that data the operational state of the well. Yet another need exists for a computer-based method of identifying and diagnosing well problems based on scanning tubing that has been removed from the well. A capability addressing one or more of these needs would promote more effective or more profitable well operation.